Typical “sucker rod” pumps are positive displacement pumps used to pump fluids from wells. These pumps are typically located in the wellbore below the liquid level of the fluid to be pumped. The pump has an elongate cylindrical barrel connected to the lower end of a string of production tubing (which extends upward to the wellhead), plus a hollow piston (also referred to as a plunger) which reciprocates up and down within the pump barrel and in sealing engagement with the inner wall of the barrel. The plunger is connected to the lower end of a string of sucker rods extending to the surface within the production tubing, with the upper end of the sucker rod string being connected to a surface-located pumping unit (such as the well-known “horsehead” or “walking beam” pump jack), which reciprocates the rod string and the plunger.
The barrel of the sucker rod pump has an inlet check valve (comprising a standing ball and seat, and alternatively referred to as a “standing valve”) at its lower end, and an outlet check valve (comprising a travelling ball and seat, and alternatively referred to as a “travelling valve”) disposed within the plunger. Formation fluids flow into the wellbore and thence into the pump barrel through the standing valve when fluid pressure is sufficient to unseat the ball in the standing valve. Downward movement of the plunger through the fluid above the standing valve forces the ball in the travelling valve open, thus allowing fluid to flow through the travelling valve and into a region of the barrel above the plunger. During the plunger's downstroke, the standing valve is closed and thus prevents fluids from flowing back into the wellbore. When the plunger begins its upstroke, the ball in the travelling valve becomes seated due to the weight of the fluid column now overlying the travelling valve, and the fluid column is therefore lifted upward by the plunger. At the same time, the upward movement of the plunger draws additional fluids from the wellbore into the barrel through the standing valve, and the pumping cycle begins again when the plunger begins its next downstroke.
These pumps have proven to be mechanically sound and reliable, but they do encounter pumping problems. When the fluid being pumped is near its flash point temperature, it will partially vaporize when it is drawn into the barrel. Any vapor or gas drawn into the barrel through the standing valve must be compressed to the pressure of the production tubing on the plunger downstroke before the travelling valve will open and allow fluids out of the pump. In other words, the pressure built up in the barrel during the plunger downstroke must overcome the hydrostatic load acting on the travelling ball due to the fluid column above the plunger, or else the travelling valve will not open. However, the compressibility of any gas in the barrel makes it more difficult to build up sufficient pressure in the barrel, and this problem worsens as the amount of gas in the barrel increases.
The pressure drop that is often increased by pressure differentials through the standing valves in conventional sucker rod pumps is partially responsible for “gas locking” and for problems achieving satisfactory fluid flow into the pump when such pumps are used to pump viscous fluids (such as heavy oil). There are many types of standing cages (i.e., cages for standing valves) designed to reduce the pressure differential across the standing valve. The volume of gas or vapor within the pump can be great enough that the full downward stroke of the plunger will not produce sufficient pressure in the pump barrel to force the travelling valve open. When this happens, the pump is said to be gas-locked (or, alternatively, “vapor locked”). Pumps used to pump crude oil containing significant amounts of lighter fractions will be particularly prone to vapor locking. When an oil field is subject to a steam flood, a mixture of oil and condensate near its flashing point is produced, which also can vapor-lock a pump.
When a pump is vapor-locked, it is typically shut in for a period of time, or, alternatively, fluid is introduced into the wellbore with a “flush-by” service rig. During the shut-in period, the gas will have a chance to escape through check valves, and the pump can cool due to the absence of the heat of compression and frictional heat created by the plunger sliding up and down within the pump barrel. The vapor lock will eventually break, allowing pumping to be continued. The use of mechanical impact or tapping bottom to solve vapor lock is unacceptable.
Conventional sucker rod pumps are also often used to lift viscous or “heavy” oils, and in such conditions the standing valves can impede efficient pump performance and production, because the restricted area around and through the ball and seat of the standing valve can limit the amount of fluid that can be drawn into the pumping chamber. Similar concerns can arise when a conventional pump is being reciprocated at high speeds. The fluid cannot completely fill the pumping chamber due to frictional drag caused by the restrictive standing valve, which acts as a choking point limiting the volume of fluid allowed into the pumping chamber. A further problem commonly arising when pumping viscous fluids using conventional pumps is that solids contained in the produced fluid often contaminate the ball and seat of the standing valve, causing the pump to cease operation.
It is common practice, when a conventional sucker rod pump becomes plugged with solids from the wellbore, to use a specialized service rig called a “flush-by unit” to clean out the pump so that it can be put back into service. The flush-by unit will lift the pump out of the seating nipple or remove the plunger and standing valve. At this stage, clean fluid is pumped down the production tubing in an effort to remove contaminating solids from the tubing string and pump components. These operations cost money in terms of both the flush-by unit and lost production time.
When conventional sucker rod pumps are employed to pump viscous wells, or wells in which wellbore deviations cause frictional drag (such as in horizontal wells), the sucker rod string may be unable to fall fast enough for satisfactory oil production to be realized. Various devices and pumps have been used in the past to increase downstroke loads in order to increase downstroke speed (i.e., strokes per minute) and thereby mitigate the frictional drag problem in deviated wellbores. However, with the increasingly common use of directional drilling to drill horizontal and other non-vertical wellbores, slower downstroke speeds continue to be a problem that limits production.
For the foregoing reasons, there is a need for a well pump which is capable of pumping volatile fluids and is resistant to gas/vapor-locking, and which will not “fluid pound” (a term well understood in the art). There is a further need for a well pump that can facilitate flushing action to remove contaminating solids from the pump without the need for a flush-by unit. In addition, there is a need for a well pump that has no standing valve, such that there is no pressure drop through the inlet valve. Furthermore, there is a need for a well pump that that is less prone to reduced downstroke speed when operating in a deviated wellbore.